Repressurized natural gas addition to main gas stream to maintain well head pressure



Jan. 2,. 1968 J. F. THORNTON ETAL 3,3

REPRESSURIZED NATURAL GAS ADDITION TO MAIN GAS STREAM TO MAINTAIN WELL HEAD PRESSURE Filed Feb. 25, 1965 30 32 36 NATURAL 4 WELL HEAD 38 44 46/0 REMQl AL DRIER 6 4 84 86FU6AS ELJENERGIZE COMPEL-$50178 a2 88 54 I [JR/5R3 l0 I 58 I I 74 I 23 I a 70 70 I LNG INVENTOR$ Ludwig Kniel BY James F. Thornton ffzyvwgfiZwz/mir ATTORN EYS United States Patent 3,360,945 REPRESSURHZED NATURAL GAS ADDITION TO MAIN GAS STREAM T0 MAINTAIN WELL HEAD PRESSURE James F. Thornton, New York, and Ludwig Kniel, Scarsd'ale, N.Y., assignors to The Lummus Company, New York, N.Y., a corporation of Delaware Filed Feb. 25, 1965, Ser. No. 435,164 7 Claims. (Cl. 62-26) ABSTRACT OF THE DESCLOSURE A process for liquefying natural gas and maintaining wellhead pressure at the source thereof wherein the gas is compressed and split into two streams, the first stream containing a volume that is no greater than one-third of the total gas volume. The first stream is cooled and a portion thereof liquefied by expansion in a pluality of stages of successively lower pressure. A portion of the still gaseous fraction withdrawn from the two higher pressure stages is employed as fuel gas and the remaining still gaseous fraction is compressed and combined with the second stream. The combined stream is compressed and passed to the well-heads to maintain the pressure thereof.

This invention relates, in general, to the liquefaction of natural gas, and more particularly, to a process combining a pressure maintenance operation with a liquefaction operation, whereby the liquefied natural gas is enriched in ethane and substantial economies, in terms of energy consumption, are effected in both the pressure maintenance and liquefaction stages.

There are many reasons for reducing natural gas to a liquefied state. One of the main reasons for liquefying natural gas is the resultant reduction of the volume of the gas to about 1/600 of the volume of natural gas in the gaseous state. Such a reduction in volume permits the storage and transportation of liquefied natural gas in containers of more economical and practical design. Additionally, in the operation of a gas distribution system it is desirable to maintain a supply of gas through peak demend periods whereby such periods can be met by liquefied gas held in storage. Another important reason is the transportation of liquefied natural gas from a source of plentiful supply to a distant market where the source and supply may not be efiicaciously joined by pipe lines and transportation in the gaseous state would be uneconomical or impossible.

In co-pending US. patent application Ser. No. 358,789 now abandoned, filed Apr. 10, 1964, and entitled, Process, there is described an improved process for the liquefaction of natural gas which comprises, briefly, compressing the gas to a point above its critical pressure, passing the compressed gas through a number of heat exchangers, expanding a liquid refrigerant in the gas to cool it to about its boiling point, and expanding the gas in stages to atmospheric pressure, thereby liquefying the major portion of it. The liquefied natural gas (LNG) can then be economically stored or transported. This process forms a part of the present invention.

In the ocean transport of liquefied natural gas between continents it is of considerable benefit to the profitability of the enterprise to be able to provide means whereby the cold potential available in such LNG can be beneficially recovered during the process of revaporization at the receiving terminal.

In a co-pending US. patent application a method for realizing this beneficial effect is described, which consists of making a separation, during the course of revaporization of the LNG, between methane and the heavier hydrocarbons, particularly ethane, presuming that such ethane, etc., is present in sufiicient quantity to render the operation worthwhile. The ethane is thermally converted into ethylene. The refrigeration effort for the purification of the ethylene-bearing stream, as well as for effecting the separation of the ethane and any higher boiling hydrocarbons form the methane, is obtained from the revaporization of the liquefied natural gas. It is desirable for such utilization of the available cold potential that the ethane content of LNG be in the order of 10 or more volume percent, depending on certain factors which are explained in the said co-pending application. Unfortunately, however, so-called non-associated or dry gases rarely contain this much ethane naturally.

An LNG product of higher ethane content can be obtained from leaner or dryer gases and the liquefaction plant can be operated more profitably, if it can be combined with a pressure maintenance plant of an oil or condensate field. The combination with which to realize these worthwhile objectives forms the substance of the present invention.

It is therefore an object of the present invention to provide an improved, combined process for liquefaction of natural gas and well-pressure maintenance which is characterized by the production of a liquefied natural gas product richer in ethane and heavier hydrocarbons and by substantial energy savings.

Other objects and advantages of the invention will be made clear in the following description of an embodiment thereof, and the novel features will be particularly pointed out in connection with the appended claims.

As is well known, pressure maintenance operations require the handling of rather large volumes of gas. For the present invention to be profitable only a portion of the available gas volume can be diverted to liquefaction. It has been determined from basic considerations that this portion should not exceed from a fourth to a third of the volume of intake gas, or that the volume of injection gas should not be less than two to three times of the volume of gas which is to be liquefied.

The minimum economical liquefaction volume for an ocean transport route depends on many factors of which one of the most important is the length of the traverse. The cost of transport which contributes materially to the cost of the gas delivered can be reduced by employing large tankers. Investigations of likely routes tend to support the view that the minimum daily liquefaction volume should be in the order of 30 to 40 million cubic feet per day. It thus follows that the invention, at least in its most efficient employment, should be utilized in repressuring plants handling from to million cubic feet or more per day.

The plant should be located close to tide water, as liquefied natural gas cannot be piped any distance without very substantial losses, nor can the volume of flash vapors from the lowest temperature stages (liquid subcooling stages) of the liquefaction plant be delivered back into the injection gas stream, as set forth hereinbelow, over any appreciable distance without impairing the economy of the combined operation.

A better understanding of the invention will be gained by referring to the following detailed description of an embodiment thereof, taken in conjunction with the single attached drawing, which is a simplified, schematic flow sheet or flow diagram illustrating a preferred embodiment of the invention. It will be understood by those skilled in the art that some of the below-described features are optional and that various changes could be made without departing from the scope of the invention.

With reference to the drawing, natural gas at about 60 p.s.i.g. in line 30 is initially compressed to about l2()014()0 p.s.i.g. in compressor 1. Compressed gas in line 32 is then treated for the removal of heavier hydrocarbons and water vapor by a first cooler 2 and a refrigcrated subcooler 3, wherein condensation of these components occurs, and the gas is then passed to separator 4 via line 34. Water and heavier hydrocarbons are removed in line 35, and the overhead stream passes out of separator 4 in line 36. At point 38, the stream is divided, a volume of gas in the order of 2 to 3 times the volume to be recovered as LNG being branched off in line 40 to by-pass the liquefaction plant. The remaining portion is passed through line 52 and the cold train of the liquefaction plant.

Gas in line 52 is first treated to remove acid components at 5, this unit having refiux circuits 54, 56 and 58. The overhead in line 60 is then fed to glycol drying stage 6 wherein any remaining water vapor is absorbed by the glycol and removed at 62. The overhead, in line 64, is cooled to F. in refrigerated subcooler 7, and any hydrocarbon condensate, lube oil or traces of glycol are removed in separator 8 via line 69. The overhead gas is then passed via lines 76, 70 to dessicant dryers 9, the streams being combined again in line 72.

A portion of the gas is utilized to reheat the fuel gas in line 14 in exchanger 10, and, after performing this function, returns to the main stream via line 13 at 76. The remainder of the stream is passed into line 74 and subcooler 11.

The recombined stream is expanded in three stages, shown schematically at 16, in accordance with the teachings in copending US. patent application Ser. No. 358,789. Liquefied natural gas is withdrawn through line 22 and sent to storage or transport.

The gases emanating from these stages, in streams 17, 18 and 20, are esssentially pure methane and noncondensibles. Because of this, the LNG withdrawn in line 22. is considerably richer in ethane, a typical increase being from 4% in the raw gas to 9% in the LNG. The gases in lines 17, 18 and 20, are compressed in recompressor 21, with the exception of fuel gas off-takes 1d, 19, which provide all the requirements for compressor drives and the like. Gases in lines 14, 19, after cold recuperation in exchanger 10, are passed in lines 89, 82, exchanger 84 and out through lines 86, 88; this arrangement provides for gas at two different pressures. It is to be noted that this measure saves considerable compression energy, as the fuel gas volume for compressor drives alone with average 18 to 20% of the total volume of gas liquefied depending, of course, on the total amount of gas handled and the injection pressure desired.

Recompressed gas in line 23 from compressor 21 is joined with compressed field gas not sent to the cold train in line at point 42. The combined streams, in line 44, are compressed to the desired injection pressure in compressor 24 passed via line 46 to cooler 25, and then to the respective wellheads of the repressuring system (not shown) via line 50.

From the foregoing, it is clear that the process of the invention has the following advantages: Firstly, the primary gas compressor 1 and related equipment will handle the entire gas volume for both liquefaction and pressure maintentance, thus cutting down on both capital and operating expenses. Secondly, removal of the flashed-off vapors in lines 17, 18, 20, amounting to about 1.38 times the amount of gas liquefied and consisting essentially of methane and noncondensibles, more than double the ethane content of the LNG. As noted hereinabove, this is most useful for the recuperation of the cold potential in the regasification process described in the aforementioned copending patent application.

Energy is conserved in two particular ways by employing the process of the invention. First, by utilizing the flash gases (lines 17, 13, 20) for fuel gas use (lines 14;, 19) for the entire plant, rather than just for the liquefaction, dependence on outside utilities is eliminated. In cases where the gas contains a high proportion of noncondensibles such as nitrogen, a further saving can be effected, as in this instance the flash vapors need not be recycled back to the feed, which would result in a higher recycle volume, but rather are boosted into the injection gas stream.

It is to be understood that various changes in the details, steps, materials and arrangements of parts, as set forth hereinabove to describe and illustrate the invention, may be made by those skilled in the art without departing from the scope of the invention as defined in the appended claims.

What is claimed is:

1. A process for liquefying natural gas and maintaining well-head pressure at the source thereof comprising:

(a) compressingsaid gas;

(b) dividing said compressed gas into first and second streams, said first stream containing not more than about one-third of the total volume of said gas;

(0) cooling said first stream to about its normal boiling point by expanding a liquefaction refrigerant in in indirect heat exchange therewith;

(d) expanding the cooled first gas stream to about atmospheric pressure in a plurality of stages of successively lower pressure whereby about one-half of said first gas stream is liquefied, the remaining gaseous fraction consisting essentially of methane and non-condensibles;

(e) recovering the liquefied portion of gas;

(f) passing a portion of the remaining gaseous fraction from a higher pressure stage of the plurality stages in an indirect heat transfer relationship with at least a portion of said first stream prior to expansion thereof, said portion of the remaining gaseous fraction being employed as a fuel gas for the process;

(g) compressing the remaining portion of gaseous fraction from the higher pressure stage and the remaining gaseous fraction from the plurality of stages;

(h) mixing the compressed stream of (g) with said second stream; and

(i) compressing and passing the combined stream of (h) to the well-heads to maintain the pressure thereof.

2. A process for liquefying natural gas and maintaining well-head pressure at the source thereof comprising:

(a) compressing the gas;

(b) dividing said compressed gas into first and second streams, said first Stream containing not more than about one-third of the total volume of the gas;

(c) cooling the first stream by indirect heat transfer with an expanding refrigerant;

(d) expanding the cooled first stream to about atmospheric pressure to liquefy a portion of said first stream, the remaining gaseous fraction consisting essentially of methane and non-condensibles;

(e) recovering the liquefied portion;

(f) combining at least a portion of the remaining gaseous fraction with the second stream; and

(g) compressing and passing the combined stream of step (f) to the well-heads to maintain the pressure thereof.

3. The process as defined in claim 2 wherein a portion of the remaining gaseous fraction is compressed prior to being combined with the second stream.

4. The process as defined in claim 3 and further comprising using a portion of the remaining gaseous fraction as fuel gas to meet the energy requirements of the process.

5. The process as defined in claim 4 wherein the first stream is expanded in a plurality of stages of decreasing pressure, the portion of the remaining gaseous fraction used as fuel gas being withdrawn from at least one of the high pressure stages of the plurality of stages.

6. The process as defined in claim 5 wherein the portion 6 used as fuel gas is Withdrawn from more than one of the 2,198,098 4/1940 Vaughan. higher pressure stages to supply fuel gas at different pres- 2,535,148 12/ 1950. Martin. sures. 2,582,148 1/1952 Nelly 6223 XR 7. The process as defined in claim 2, wherein c0mpres 2,720,265 10/ 1955 Tracht. sion in step (a) is to about 1,200 to 1,400 p.s.i.g., and 5 3,160,489 12/1964 Brocoff et a1. 62-23 XR compression in step (g) is to at least about 2,000 p.s.i.g. 3,182,461 5/1965 Johanson 62-23 XR 3,223,157 12/1965 Lacey et a1 166-7 References Cited 3,257,813 6/1966 Tafreshi 62-23 UNITED STATES PATENTS 1,1 0, 4 8/1915 Robarts. 10 NORMAN YUDKOFF, Plzmar'y Exammel.

2,082,189 6/ 1937 Twomey, V. W. PRETKA, Assistant Examiner. 

